1. Technical Field
Embodiments of the present disclosure relates generally to hydrocarbon production and, more particularly, to real-time detection of the influx of gas into a wellbore during drilling operations.
2. Background Description
The following descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section.
Exploration and production of hydrocarbons commonly include using a drill bit attached to a bottom hole assembly (BHA), which is in turn attached to a length of hollow drill pipe reaching to the surface to drill a well. Drilling fluid, or “mud,” is injected down the conduit formed by the drill pipe, through the BHA, and out of the drill string into the annulus between the drill pipe and the borehole through nozzles in the drill bit. The drilling mud has many functions, including lifting the rock cuttings generated by the drill bit and transporting them to the surface; lubricating and cooling the drill bit; generating power for the instruments mounted in the BHA; acting as a telemetry conduit for acoustic pulses propagating inside the drill pipe; and maintaining hydraulic pressure on the formation to prevent unwanted influx of oil, gas or water into the borehole during the drilling process.
With respect to this latter function, drilling operators typically vary the mixture of gases, liquids, gels, foams and/or solids mixed into the drill mud and injected into the drill pipe to maintain hydraulic pressure at desired levels. In addition, drilling operators typically adjust a choke at the surface to regulate back pressure on the circulation of the fluids in the annulus between the drill pipe and the borehole. By controlling the hydrostatic and back pressure, production of fluid from the penetrated zones may be controlled from the surface during drilling.
However, on occasion, the pressure the drill mud exerts on the formation may fall below the pressure of fluid in the pores of the formation, or in pre-existing fractures in the formation. When this occurs, pore fluids may flow unintentionally into the borehole. Such an event is referred to as a “kick” and can cause undesirable conditions, particularly if the fluid flowing into the borehole is a gas or a fluid containing a dissolved gas. Since the gas “kick” expands dramatically as it migrates up the borehole to regions of lower hydrostatic pressure, a gas kick event could require the well to be shut in at the blow-out preventer, and time consuming measures must be taken to gradually release the gas from the annulus in a controlled manner. In extreme cases, if the kick is not detected, a blow-out can occur.
Known methods for detecting abnormal formation pressure which could be indicative of a gas kick generally are based on measurements of various drilling parameters, including rate of penetration, torque and drag, drilling mud parameters (e.g., mud-gas cuttings), flow line mud weight, pressure kicks, flow line temperature, mud level in the mud pits, mud flow rate, shale cutting parameters (e.g., bulk density, shale factor, volume and size of shale cuttings), etc. All of these measurements suffer from the drawback that there is substantial delay between the influx of the gas into the borehole and its manifestation in these measurements at the surface. Because of this delay, corrective action may not be initiated in as timely a manner as may be desired.
Other known methods for detecting kicks rely on downhole density measurements of the borehole fluid. Limitations of these methods include the fact that the dissolved gas that may be a precursor to a kick may not be detected; the sensor provides only a point measurement and is insensitive to gas elsewhere in the mud column, particularly at locations above the sensor; distinguishing changes in mud density from fluctuations in formation density can be difficult; and some techniques may require a radioactive source.